Integrated NGL Recovery In the Production Of Liquefied Natural Gas

ABSTRACT

Process for the liquefaction of natural gas and the recovery of components heavier than methane where natural gas is cooled and separated in a first distillation column into an overhead vapor enriched in methane and a bottoms stream enriched in components heavier than methane, where the first distillation column utilizes a liquefied methane-containing reflux stream. This reflux stream may be provided by a condensed portion of the overhead vapor or a portion of totally condensed overhead vapor that is subsequently warmed. The bottoms stream may be separated in one or more additional distillation columns to provide one or more product streams, any of which are partially or totally withdrawn as recovered hydrocarbons. A stream of unrecovered liquid hydrocarbons may be combined with either the condensed portion of the overhead vapor or a portion of totally condensed overhead vapor that is subsequently warmed.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a Continuation-In-Part of Ser. No. 11/491,329, which was filed on Jul. 21, 2006, and which is incorporated herein by reference.

BACKGROUND

Raw natural gas comprises primarily methane and also contains numerous minor constituents which may include water, hydrogen sulfide, carbon dioxide, mercury, nitrogen, and light hydrocarbons typically having two to six carbon atoms. Some of these constituents, such as water, hydrogen sulfide, carbon dioxide, and mercury, are contaminants which are harmful to downstream steps such as natural gas processing or the production of liquefied natural gas (LNG), and these contaminants must be removed upstream of these processing steps. The hydrocarbons heavier than methane typically are condensed and recovered as natural gas liquids (NGL) and fractionated to yield valuable hydrocarbon products.

The first step in the NGL recovery process utilizes a distillation column or scrub column to separate the hydrocarbons heavier than methane from the pretreated natural gas feed to yield purified methane for liquefaction and NGL for separation and recovery. This process utilizes cooling, partial condensation, and fractionation steps that require significant amounts of refrigeration. This refrigeration may be provided by work expansion of pressurized natural gas feed and vaporization of the resulting condensed hydrocarbons. Additional refrigeration typically is provided by external closed-loop refrigeration using a refrigerant such as propane and/or a mixed refrigerant to liquefy the methane in the main heat exchanger. Reflux for the NGL scrub column may utilize a portion of the partially-liquefied natural gas from the main heat exchanger.

It is desirable to recover NGL from pressurized natural gas without reducing the natural gas feed pressure significantly. This allows the natural gas product (for example, pipeline gas or LNG) to be provided at or slightly below the feed pressure so that feed and/or product recompression is not required. It is also desirable to eliminate the need for scrub column overhead compression and to simplify the main heat exchanger design when a portion of the liquefied natural gas is withdrawn from the main heat exchanger for use as scrub column reflux. These needs are addressed by the embodiments of the present invention described below and defined by the claims that follow.

BRIEF SUMMARY

There are several aspects of the method and apparatus as outlined below.

Aspect 1: A process for the liquefaction of natural gas and the recovery of components heavier than methane from the natural gas, wherein the process comprises:

(a) introducing a natural gas feed into a first distillation column and separating in the first distillation column the natural gas feed into an overhead vapor enriched in methane and a bottoms liquid enriched in components heavier than methane;

(b) withdrawing from the first distillation column a first overhead vapor stream enriched in methane and a bottoms liquid stream enriched in components heavier than methane;

(c) cooling the first overhead vapor stream enriched in methane to provide a cooled overhead stream enriched in methane, combining the cooled overhead stream enriched in methane with a liquefied natural gas reflux stream to provide a two-phase mixture, and separating the two-phase mixture to provide a liquid reflux stream and a second overhead vapor stream enriched in methane;

(d) introducing the liquid reflux stream into the first distillation column to provide reflux to the distillation column;

(e) introducing the second overhead vapor stream enriched in methane into a main heat exchanger comprising only two tube bundles, said bundles consisting of a warm bundle and a cold bundle, and cooling and liquefying the second overhead vapor stream in the warm bundle to provide a single-phase, liquefied natural gas product; and

(f) subcooling at least a portion of the liquefied natural gas product in the cold bundle of the main heat exchanger to provide a subcooled liquefied natural gas product, and withdrawing the subcooled liquefied natural gas product from the main heat exchanger.

Aspect 2: The process of Aspect 1, wherein the liquefied natural gas reflux stream comprises: a portion of the single-phase, liquefied natural gas product, withdrawn from the main heat exchanger between the warm and cold bundles; a portion of the subcooled liquefied natural gas product; and/or liquefied natural gas obtained from processing and/or storing at least a portion of the subcooled liquefied natural gas product.

Aspect 3: The process of Aspect 1 or 2, wherein the method further comprises the step of withdrawing from the main heat exchanger, between the warm and cold bundles, a first portion of the liquefied natural gas product, the liquefied natural gas reflux stream comprising said first portion of the liquefied natural gas product; and wherein step (f) comprises subcooling a second portion of the liquefied natural gas product in the cold bundle of the main heat exchanger to provide a subcooled liquefied natural gas product, and withdrawing the subcooled liquefied natural gas product from the main heat exchanger.

Aspect 4: The process of any preceding Aspects, wherein the method further comprises the steps of: separating the bottoms liquid stream in one or more additional distillation columns to provide one or more hydrocarbon product streams selected from the group consisting of a residual vapor stream comprising methane, a liquid stream enriched in ethane, a liquid stream enriched in propane, a liquid stream enriched in butane, and a liquid stream enriched in pentane; and withdrawing as recovered hydrocarbons all or a portion of any of the one or more hydrocarbon product streams.

Aspect 5: The process of Aspect 4, wherein step (c) comprises: combining the first overhead vapor stream enriched in methane with a stream of unrecovered hydrocarbons, cooling the combined stream to provide the cooled overhead stream enriched in methane, combining the cooled overhead stream enriched in methane with the liquefied natural gas reflux stream to provide the two-phase mixture, and separating the two-phase mixture to provide the liquid reflux stream and the second overhead vapor stream enriched in methane.

Aspect 6: The process of Aspect 5, wherein the stream of unrecovered liquid hydrocarbons comprises any of: (I) a portion of the liquid stream enriched in ethane, (II) a portion of the liquid stream enriched in propane, (Ill) a portion of the liquid stream enriched in butane, (IV) a portion of the liquid stream enriched in pentane, and (V) all or a portion of the residual vapor stream dissolved in a portion of the liquid stream enriched in propane and/or a portion of the liquid stream enriched in butane and/or a portion of the liquid stream enriched in pentane.

Aspect 7: The process of any preceding Aspects, wherein in step (c) the first overhead vapor stream is cooled to a temperature of from −20 to −70° F. (−29 to −57° C.).

Aspect 8: The process of any preceding Aspects, wherein the natural gas feed is cooled prior to being introduced into the first distillation column.

Aspect 9: The process of Aspect 8, wherein the natural gas feed is cooled to a temperature of from 10 to −30° F. (12 to −34° C.) prior to being introduced into the first distillation column.

Aspect 10: The process of Aspects 8 or 9, wherein the cooling of the first overhead vapor stream enriched in methane to provide the cooled overhead stream enriched in methane, and the cooling of the natural gas feed prior to said natural gas feed being introduced into the first distillation column, is carried out using the same refrigerant.

Aspect 11: The process of any preceding Aspects, wherein the liquid reflux stream is introduced into the top of the first distillation column.

Aspect 12: The process of any preceding Aspects, wherein boilup for the first distillation column is provided by vaporizing a portion of the bottoms liquid in a reboiler.

Aspect 13: The process of any preceding Aspect, wherein the cooling and liquefying of the second overhead vapor stream in the warm bundle of the main heat exchanger is effected by indirect heat exchange with a first vaporizing refrigerant provided by reducing the pressure of a first cooled multicomponent liquid refrigerant.

Aspect 14: The process of Aspect 13, wherein the first cooled multicomponent liquid refrigerant is provided by cooling a first multicomponent refrigerant in the warm bundle of the main heat exchanger.

Aspect 15: The process of any preceding Aspects, wherein the subcooling of the at least a portion of the liquefied natural gas product in the cold bundle of the main heat exchanger is effected by indirect heat exchange with a second vaporizing refrigerant provided by reducing the pressure of a second cooled multicomponent liquid refrigerant.

Aspect 16: The process of Aspect 15, wherein the second cooled multicomponent liquid refrigerant is provided by cooling a second multicomponent refrigerant in the warm and cold bundles of the main heat exchanger.

Aspect 17: The process of any preceding Aspects, wherein the flow rate of the cooled overhead stream enriched in methane is greater than the flow rate of the liquefied natural gas reflux stream, such that the cooled overhead stream provides the majority of the two-phase mixture.

Aspect 18: The process of Aspect 17, wherein the flow rate of the liquefied natural gas reflux stream is less than 10% of the sum of the flow rates of the liquefied natural gas reflux stream and the cooled overhead stream.

Aspect 19: An apparatus for the liquefaction of natural gas and the recovery of components heavier than methane from the natural gas, wherein the apparatus comprises:

(a) a first distillation column adapted to separate a natural gas feed into an overhead vapor enriched in methane and a bottoms liquid enriched in components heavier than methane and thereby provide a first overhead vapor stream enriched in methane and a bottoms liquid stream enriched in components heavier than methane;

(b) a cooling system adapted to cool the first overhead vapor stream enriched in methane to provide a cooled overhead stream enriched in methane;

(c) a reflux drum adapted to receive a two-phase mixture, formed from the combination of the cooled overhead stream enriched in methane and a liquefied natural gas reflux stream, and adapted to separate the two-phase mixture to provide a liquid reflux stream and a second overhead vapor stream enriched in methane;

(d) piping adapted to introduce the cooled overhead stream and the liquefied natural gas reflux stream, as separate streams or as a combined stream, into the reflux drum;

(e) piping adapted to introduce the liquid reflux stream into the first distillation column to provide reflux to the distillation column;

(f) a main heat exchanger comprising only two tube bundles, said bundles consisting of a warm bundle and a cold bundle, the warm bundle being adapted to cool and liquefy the second overhead vapor stream to provide a single-phase, liquefied natural gas product, and the cold bundle being adapted to subcool at least a portion of the liquefied natural gas product to provide a subcooled liquefied natural gas product;

(g) piping adapted to introduce the second overhead vapor stream into the warm bundle of the main heat exchanger; and

(h) piping adapted to withdraw the liquefied natural gas product stream from the cold bundle of the main heat exchanger.

Aspect 20: The apparatus of Aspect 19, wherein said piping adapted to introduce the liquefied natural gas reflux stream into the reflux drum is adapted to withdraw a portion of the liquefied natural gas product from the main heat exchanger between the warm and cold bundles, to withdraw a portion of the subcooled liquefied natural gas product and/or to withdraw liquefied natural gas obtained from processing and/or storing at least a portion of the subcooled liquefied natural gas product, the liquefied natural gas reflux stream comprising said portion of the liquefied natural gas product, said portion of the subcooled liquefied natural gas product and/or said liquefied natural gas obtained from processing and/or storing at least a portion of the subcooled liquefied natural gas product.

Aspect 21: The apparatus of Aspect 19 or 20, wherein the apparatus further comprises:

(i) one or more additional distillation columns adapted to separate the bottoms liquid stream in provide one or more hydrocarbon product streams selected from the group consisting of a residual vapor stream comprising methane, a liquid stream enriched in ethane, a liquid stream enriched in propane, a liquid stream enriched in butane, and a liquid stream enriched in pentane; and

(j) piping adapted to withdraw as recovered hydrocarbons all or a portion of any of the one or more hydrocarbon product streams.

Aspect 22: The apparatus of Aspect 21, wherein the apparatus further comprises piping adapted to introduce a stream of unrecovered hydrocarbons into the first overhead vapor stream enriched in methane prior to the resulting combined stream being cooled in the cooling system, wherein the stream of unrecovered liquid hydrocarbons is withdrawn from one of the additional distillation columns and comprises any of: (I) a portion of the liquid stream enriched in ethane, (II) a portion of the liquid stream enriched in propane, (III) a portion of the liquid stream enriched in butane, (IV) a portion of the liquid stream enriched in pentane, and (V) all or a portion of the residual vapor stream dissolved in a portion of the liquid stream enriched in propane and/or a portion of the liquid stream enriched in butane and/or a portion of the liquid stream enriched in pentane.

Aspect 23: The apparatus of any one of Aspects 19 to 22, wherein the apparatus further comprises a precooling system adapted to cool the natural gas feed prior to said feed being introduced into the first distillation column.

Aspect 24: The apparatus of Aspect 23, wherein said cooling system, adapted to cool the first overhead vapor stream enriched in methane to provide a cooled overhead stream enriched in methane, and said precooling system, adapted to cool the natural gas feed prior to said feed being introduced into the first distillation column, are adapted to utilize the same refrigerant.

Aspect 25: The process or apparatus of any preceding Aspect, wherein the main heat exchanger is a wound coil heat exchanger comprising only two wound coil tube bundles, said bundles consisting of said warm bundle and said cold bundle.

BRIEF DESCRIPTION OF SEVERAL VIEWS OF THE DRAWINGS

FIG. 1 is a schematic process flow diagram of an embodiment of the invention.

FIG. 2 is a schematic process flow diagram of another embodiment of the invention.

FIG. 3 is a schematic process flow diagram of an alternative embodiment of the invention.

FIG. 4 is a schematic process flow diagram of a process alternative that may be utilized with any embodiment of the invention.

FIG. 5 is a schematic process flow diagram an exemplary NGL fractionation system that may be utilized with any embodiment of the invention.

FIG. 6 is a schematic process flow diagram of an alternative embodiment of the invention.

FIG. 7 is a schematic process flow diagram of a traditional integrated system for LNG production and NGL recovery, utilizing a three bundle main heat exchanger.

FIG. 8 is a schematic process flow diagram of a yet further alternative embodiment of the invention.

FIG. 9 is a schematic process flow diagram of an exemplary refrigeration system that may be used with the embodiments of the invention depicted in FIGS. 6 and 8.

DETAILED DESCRIPTION

The embodiments of the invention provide improved integrated processes for NGL recovery in the production of LNG that simplify the equipment configuration by eliminating the need for feed expansion and scrub column overhead compression. In addition, when the scrub column utilizes reflux comprising scrub column overhead that is condensed in a wound coil main heat exchanger, there is no need for splitting the warm bundle of the heat exchanger to partially condense the column overhead, and a phase separator to recover the liquid required for reflux is not required. In addition, there is no need for compression and condensation of deethanizer overhead vapor to provide scrub column reflux.

Reflux for the scrub column in the embodiments described below is provided by various combinations of condensed scrub column overhead vapor and unrecovered liquid hydrocarbons from the NGL recovery system. In the present disclosure, the terms “recovered hydrocarbon” and “recovered hydrocarbons” are equivalent and mean any hydrocarbon stream withdrawn from the integrated LNG production and NGL recovery system as a product that is exported from the integrated system. The recovered hydrocarbons may be exported as one or more product streams enriched in any of the hydrocarbons in the natural gas feed. The exported streams may include, for example, any of an enriched ethane stream, an enriched propane stream, an enriched butane plus isobutane stream, an enriched pentane plus isopentane stream, and a mixed methane-ethane stream enriched in ethane. The LNG product may be considered as a recovered hydrocarbon. The term “unrecovered liquid hydrocarbon” and “unrecovered liquid hydrocarbons” are equivalent and mean any liquid portion of the hydrocarbons separated in the NGL recovery system that are not immediately present in the product streams of the recovered hydrocarbons that are exported from the integrated LNG production and NGL recovery system. Unrecovered liquid hydrocarbons may be considered as internal recycle streams within the integrated LNG production and NGL recovery system.

The term “enriched” as applied to any stream withdrawn from a process means that the withdrawn stream contains a concentration of a particular component that is higher than the concentration of that component in the feed stream to the process. Reflux is defined as a stream introduced into a distillation column at any location above the location at which the feed is introduced into the column, wherein the reflux comprises one or more components previously withdrawn from the column. Reflux typically is liquid but may be a vapor-liquid mixture.

The indefinite articles “a” and “an” as used herein mean one or more when applied to any feature in embodiments of the present invention described in the specification and claims. The use of “a” and “an” does not limit the meaning to a single feature unless such a limit is specifically stated. The definite article “the” preceding singular or plural nouns or noun phrases denotes a particular specified feature or particular specified features and may have a singular or plural connotation depending upon the context in which it is used. The adjective “any” means one, some, or all indiscriminately of whatever quantity. The term “and/or” placed between a first entity and a second entity means one of (1) the first entity, (2) the second entity, and (3) the first entity and the second entity.

A first embodiment of the invention is shown in the integrated LNG production and NGL recovery system illustrated by FIG. 1. Pretreated pressurized natural gas feed in line 100 contains primarily methane with heavier hydrocarbons in the C2-C6 range. Contaminants comprising water, CO₂, H₂S, and mercury are removed in an upstream pretreatment system (not shown) by known methods. The feed gas, typically provided at a pressure between 600 and 900 psia and ambient temperature, is cooled in heat exchanger 110 to between −20° F. and −35° F. to provide a cooled feed stream in line 112.

Heat exchanger 110 may include multiple stages of cooling by evaporating propane at different pressures; alternatively or additionally, other means of cooling may be used, such as vaporizing mixed refrigerant in a single exchanger. This stream, which may be further cooled in optional economizer heat exchanger 114, is introduced via line 116 to first distillation column or scrub column 118.

Scrub column 118 separates the feed provided via line 116 into a bottoms liquid product in line 134 that is enriched in hydrocarbons heavier than methane and an overhead vapor product in line 120 that is enriched in methane. A portion of the bottoms liquid may be withdrawn via line 130 and vaporized in reboiler 132 to provide boilup for the scrub column. The reboiler may cool a portion (not shown) of stream 100 to provide heat therein for vaporizing the liquid in line 130. The scrub column may also have an intermediate reboiler (not shown) above the bottom of the column and below the location of feed line 116, and this reboiler also may be heated by a portion of the feed stream.

The bottoms liquid in line 134 flows to generic NGL fractionation system 136. The NGL feed stream typically is reduced in pressure (not shown) and separated in or more additional distillation columns including any of a demethanizer, a deethanizer, a depropanizer, a debutanizer, and a depentanizer to provide two or more hydrocarbon fractions. In the exemplary generic NGL fractionation system of FIG. 1, three streams of recovered hydrocarbons are withdrawn and exported from the integrated LNG production and NGL recovery system as C2, C3, and C4 product streams representing streams enriched in ethane, propane, and butane plus isobutane, respectively. Unrecovered liquid hydrocarbons are withdrawn from the NGL recovery system via line 138.

The overhead vapor stream enriched in methane is withdrawn from scrub column 118 via line 120 and may be warmed by indirect heat exchange with the feed stream in line 112 in economizer heat exchanger 114. The resulting warmed overhead vapor stream in line 122 is cooled, totally condensed, and optionally subcooled in passage 123 of the first or warm (lower) bundle of wound coil main heat exchanger 124 to provide a condensed methane-enriched stream in line 125. A first portion of the liquid in line 125 is withdrawn from line 125 downstream of passage 123 and pumped by pump 127 to provide a liquefied methane-containing reflux stream. The liquefied methane-containing reflux stream is combined with the unrecovered liquid hydrocarbons in line 138 and returned to the top of scrub column 118 as a combined liquid reflux steam. Alternatively, liquefied methane-containing reflux stream from pump 127 may be introduced into the top of scrub column 118 and the unrecovered liquid hydrocarbons in line 138 may be introduced into scrub column 118 at a separate location (not shown) below the top of the column and above the location at which the cooled feed is introduced into the column via line 116. In another alternative, the liquefied methane-containing reflux stream from pump 127 and the unrecovered hydrocarbons in line 138 may be introduced into the top of scrub column 118 as separate streams (not shown).

Typically, depending on the composition of the feed in line 100, the molar flow rate of the unrecovered liquid hydrocarbons in line 138 is less than about 25% of the molar flow rate of the methane-rich stream in line 126. If the natural gas feed in line 100 does not contain a sufficient amount of the components needed to provide the unrecovered liquid hydrocarbon stream in line 138, the necessary components may be imported from any appropriate source.

The second portion of the condensed methane-enriched stream in line 125 is further cooled in passage 128 the second or cold (upper) bundle of wound coil main heat exchanger 124 and withdrawn as LNG product via line 129. The LNG may be reduced in pressure before and/or after subcooling in the cold bundle if desired. If the LNG product is stored at high pressure (PLNG), there is no need for subcooling, and the cold bundle is not required. It is possible to use a portion of the LNG product in line 129 as a methane-rich reflux to scrub column 118 if desired, but such a configuration would waste refrigeration by providing reflux at a temperature much lower than required.

The temperature of the liquefied methane-containing reflux stream withdrawn from main heat exchanger 124 via line 126 and pump 127 in FIG. 1 may be lower than that actually required based on the temperature at the top of scrub column 118. In order to match the temperature of the methane-rich reflux to the temperature at the top of scrub column 118, the warm bundle of main heat exchanger 124 would have to be split to allow the withdrawal of a methane-rich reflux stream at an intermediate location. In addition, a phase separator would be required when the withdrawn stream is a mixed vapor-liquid stream. The thermodynamic inefficiency of providing the reflux at a temperature colder than required in the embodiment of FIG. 1, however, is compensated for by eliminating the need to split the warm bundle of main heat exchanger 124.

Refrigeration to main heat exchanger 124 may be provided by any known refrigeration system used in the production of LNG. For example, as shown in FIG. 1, a single mixed refrigerant (MR) system may be used in which a liquid refrigerant is provided via line 152 and a vapor refrigerant is provided via line 156. The vapor in line 156 is condensed and cooled in main heat exchanger 124 and expanded through throttling valve 158 to provide a first vaporizing refrigerant to the cold (upper) bundle of the exchanger and subsequently to the warm (lower) bundle of the exchanger. Liquid refrigerant 152 is cooled in main heat exchanger 124 to yield subcooled liquid refrigerant in line 153, expanded through throttling valve 154, and combined with vaporizing refrigerant from the cold (upper) bundle at a location near the cold end of the warm bundle of the main heat exchanger. As an alternative to throttling valves 154 and/or 158, as well as the LNG product letdown valve, expansion may be effected by isentropic dense fluid expanders (hydraulic turbines).

The refrigerant streams are completely vaporized and leave main heat exchanger 124 as refrigerant vapor via line 150. The mixed refrigerant vapor flows to a refrigeration system (not shown) where it is compressed, cooled by multiple stages of vaporizing propane, and separated to provide liquid refrigerant 152 and lighter vapor refrigerant 156.

Any other refrigeration system or a combination of systems known in the art may be used to provide refrigeration to main heat exchanger 124. For example, the pure fluid cascade and isentropic vapor expansion process may be used as described in U.S. Pat. No. 6,308,531, which is incorporated herein by reference.

Using a portion of condensed scrub column overhead as methane-enriched reflux via line 126 in the embodiment of FIG. 1 avoids breaking the warm bundle of the main heat exchanger 124 into two separate bundles to withdraw a methane-rich stream for use as reflux. It also eliminates the potential need for separating a two-phase methane-rich stream in a phase separator if the methane-rich stream is a vapor-liquid mixture in order to use the liquid portion as reflux and redistribute the vapor portion for further condensation in the main heat exchanger. A smaller phase separator may be required at startup as explained below. Using economizer heat exchanger 114 ensures that the overhead stream in line 122 enters main heat exchanger 124 at about the same temperature as the refrigerant streams in lines 152 and 156, which typically are generated by propane refrigeration.

The use of unrecovered liquid hydrocarbons via line 138 as additional reflux to scrub column 118 eliminates the need for expanding the column feed and recompressing the column overhead. To minimize power consumption, the natural gas feed pressure should be significantly above the critical pressure of methane. At the same time, the scrub column must be operated below the critical pressure of the feed mixture in order to achieve separation. A common solution known in the art is to isentropically expand the scrub column feed and then to recompress the overhead vapor product. Work obtained from the isentropic expansion of the feed can be used to at least partially drive the overhead compressor or compressors. Such a solution is shown, for example, in U.S. Pat. No. 4,065,267 and in FIG. 2 of a paper by Elliot, Qualls, Huang, Chen, Lee, Yao, and Zhang entitled “Benefits of Integrating NGL Extraction and LNG Liquefaction Technology” presented at the AIChE Spring Meeting, April 2005.

Another embodiment of the invention is illustrated in FIG. 2. In this embodiment, a portion of the scrub column overhead vapor in line 120 is withdrawn via line 220 and condensed in heat exchanger 200 to produce a liquefied methane-containing reflux stream that is combined with the unrecovered liquid hydrocarbons in line 138 and introduced as a combined stream via line 221 to the top of scrub column 118. The liquefied methane-containing reflux stream from heat exchanger 200 may be pumped if necessary.

Alternatively, the liquefied methane-containing reflux stream from heat exchanger 200 may be introduced into the top of scrub column 118 and the unrecovered liquid hydrocarbons in line 138 may be introduced into scrub column 118 at a separate location (not shown) below the top of the column and above the location at which the cooled feed is introduced into the column via line 116. In another alternative, the liquefied methane-containing reflux stream from heat exchanger 200 and the unrecovered liquid hydrocarbons in line 138 may be introduced into the top of scrub column 118 as separate streams (not shown).

Refrigeration for main heat exchanger 124 is provided in the same manner as described above with reference to FIG. 1 to provide liquid refrigerant 152 and vapor refrigerant 156. Refrigeration for heat exchanger 200 is provided by withdrawing a portion of the liquid mixed refrigerant in line 153 via line 252, reducing the pressure of the refrigerant through throttling valve 254, and introducing the reduced-pressure refrigerant into the heat exchanger. Vaporized mixed refrigerant from heat exchanger 200 is combined with vaporized mixed refrigerant from main heat exchanger 124 to provide the vaporized refrigerant in line 150. Alternatively, refrigerant in line 252 may be withdrawn from line 152 prior to main heat exchanger 124, expanded to an intermediate pressure or pressures, vaporized in heat exchanger 200, and returned to the mixed refrigerant compressor (not shown) at an appropriate stage location or locations. All other process features of FIG. 2 are identical to those described above with reference to FIG. 1.

In an alternative version of the process described above with reference to FIG. 2, situations may arise in which it is desirable to export all hydrocarbons recovered in the bottoms from scrub column 118 and fractionated in the NGL fractionation system. In this case, the flow rate of the unrecovered hydrocarbon stream in line 138 would be zero, and scrub column 118 would utilize reflux in line 221 provided by condensing the portion of the scrub column 118 overhead stream in line 220 in heat exchanger 200.

An alternative embodiment of the invention is illustrated in FIG. 3. In this embodiment, the liquefied methane-containing reflux stream from pump 127 is warmed in heat exchanger 300 by indirect heat exchange with a portion of mixed refrigerant liquid withdrawn from line 152 via line 352. In this case, the combined reflux stream is closer to its optimum temperature when it is introduced into scrub column 118. Cooled refrigerant from heat exchanger 300 flows via line 302 and is combined with the refrigerant in line 153 prior to throttling valve 154.

Alternatively, the condensed methane-rich stream from heat exchanger 300 may be introduced into the top of scrub column 118 and the unrecovered hydrocarbons in line 138 may be introduced into scrub column 118 at a location (not shown) below the top of the column and above the location at which the cooled feed is introduced into the column via line 116. In another alternative, the liquefied methane-containing reflux stream from heat exchanger 300 and the unrecovered liquid hydrocarbons in line 138 may be introduced into the top of scrub column 118 as separate streams (not shown). All other process features of FIG. 3 are identical to those described above with reference to FIG. 1.

In an alternative version of the process described above with reference to FIG. 3, situations may arise in which it is desirable to export all hydrocarbons recovered in the bottoms from scrub column 118 and fractionated in the NGL fractionation system. In this case, the flow rate of the unrecovered hydrocarbon stream in line 138 would be zero, and scrub column 118 would utilize reflux provided by warming in heat exchanger 300 the portion provided by pump 127 of the totally condensed overhead from scrub column 118.

FIG. 4 shows an optional configuration that can be used to return the condensed methane-enriched stream in line 126 to scrub column 118. The condensed methane-enriched stream in line 126 is reduced in pressure through throttle valve 426 to its bubble point, introduced into drum 427 that maintains some vapor inventory, and pumped by pump 127 to the scrub column pressure. A portion of the pumped stream is recycled to drum 427 through valve 428 to maintain the liquid level in the drum and the remaining portion flows to scrub column 118 through optional valve 429. During plant startup, excess vapor may be vented (not shown) from the top of drum 427 and flared or compressed and recovered. Since the condensed methane-enriched stream in line 126 is only a small portion of the total LNG stream and there is no net vapor flow during normal operations, drum 127 is much smaller than a reflux drum typically used in a conventional plant to separate a partially condensed methane-rich stream withdrawn from the main heat exchanger to provide reflux liquid to the scrub column.

Throttling valve 426 and drum 427 can be avoided by detecting liquid in line 126 (for example with a thermocouple) and redirecting vapor or two-phase flow from the main heat exchanger 124 at a startup situation (at normal operation it is subcooled liquid) to another existing drum such as helium recovery or fuel gas flash drum or simply by flaring it. In another alternative, the system can be simplified by using a type of pump 127 that can tolerate two-phase flow at off-design conditions, such as a cryogenic gear or screw pump or a centrifugal pump with a high-performance inducer.

An exemplary NGL recovery system that can be used with embodiments of the present invention is illustrated in FIG. 5 and comprises four distillation columns including demethanizer 501, deethanizer 503, depropanizer 505, and debutanizer 507 operating in series. Bottoms liquid from scrub column 118 via line 134 is cooled in heat exchanger 509 to approximately ambient temperature and flows to demethanizer column 501. Overhead vapor containing methane and some ethane is withdrawn from the top of the demethanizer as a recovered hydrocarbon stream via line 509 and may used as fuel or liquefied and reinjected into the LNG product. A bottoms liquid enriched in ethane and heavier hydrocarbons is withdrawn via line 511 and is partially vaporized in heat exchanger 513, boilup vapor is returned to the column via line 517, and the remaining stream flows via line 519 and valve 521 into deethanizer column 503.

High purity ethane vapor is withdrawn from the column via line 523 and is condensed in overhead condenser 525. A portion of the condensed liquid is returned as reflux via line 527 and another portion is withdrawn via line 529 as a recovered hydrocarbon comprising high purity ethane typically containing greater than 98 mole % ethane. The bottoms liquid from the deethanizer via line 531 is partially vaporized in heat exchanger 533, boilup vapor is returned to the column via line 535, and the remaining stream flows via line 537 and valve 539 into depropanizer column 505. High purity propane vapor is withdrawn from the column via line 541 and is condensed in overhead condenser 543. A portion of the condensed liquid is returned as reflux via line 545 and another portion is withdrawn via line 547 as a recovered hydrocarbon comprising high purity propane typically containing greater than 98 mole % propane.

The bottoms liquid from the depropanizer via line 549 is partially vaporized in heat exchanger 551, boilup vapor is returned to the column via line 553, and the remaining stream flows via line 555 and valve 557 into debutanizer column 507. High purity butane (plus isobutane if present) vapor is withdrawn from the column via line 559 and is condensed in overhead condenser 561. A portion of the condensed liquid is returned as reflux via line 563 and another portion is withdrawn via line 565 as a recovered hydrocarbon comprising high purity butane (plus isobutane if present) typically containing greater than 98 mole % butane plus isobutane. The bottoms liquid from the debutanizer is withdrawn via line 567 and partially vaporized in heat exchanger 569, boilup vapor is returned to the column via line 571, and the remaining stream is withdrawn via line 573 as a recovered hydrocarbon comprising pentane (plus isopentane if present) and heavier hydrocarbons.

In this illustration, propane and butane liquid streams may be withdrawn as unrecovered liquid hydrocarbons via lines 575 and 577, respectively, and mixed in line 579. The mixed unrecovered liquid hydrocarbon stream is cooled to temperature of vaporizing propane refrigerant in heat exchanger 581, is pumped to scrub column pressure in pump 583, and flows via line 138 to the scrub column in any of the embodiments of FIGS. 1, 2, and 3. Optionally, a portion of the ethane liquid from the deethanizer may be withdrawn as unrecovered liquid hydrocarbon via line 585 and combined with the unrecovered propane and/or butane in line 579. Optionally, a portion of the overhead vapor in line 509 from demethanizer 501 may be withdrawn via line 587 and absorbed in the unrecovered liquid propane and/or butane in line 579. No compression of the demethanizer overhead vapor is needed in this option. In one alternative, all butane from the debutanizer is recovered via line 565 and none is withdrawn as unrecovered liquid hydrocarbon via line 577. In another alternative, all propane from the depropanizer is recovered via line 547 and none is withdrawn as unrecovered liquid hydrocarbon via line 575. In general, any of the dissolved overhead from demethanizer 501 and the condensed ethane, propane, and butane overhead streams from deethanizer 503, depropanizer 505, and debutanizer 507, respectively, may be wholly or partially withdrawn as unrecovered liquid hydrocarbons for return to scrub column 118 as long as the withdrawn hydrocarbon product requirements are satisfied.

FIG. 6 shows another embodiment of the invention in which pretreated pressurized natural gas feed stream in line 600 is introduced into the distillation column or scrub column 618 at an intermediate location. Again, the pretreated pressurized natural gas feed stream in line 600 contains primarily methane with heavier hydrocarbons in the C2-C6 range. Contaminants comprising water, CO₂, H₂S, and mercury are removed in an upstream pretreatment system (not shown) by known methods. As previously stated, the pretreated pressurized natural gas feed stream in line 600 may be introduced at ambient temperature into the scrub column 618, but is preferably pre-cooled to a temperature of between 10 and −30° F. in a precooler 610 before being introduced in line 612 into the scrub column 618. Again, heat exchange in said precooler may be accomplished by evaporating propane at a single pressure in a single stage or by evaporating propane at different pressures in multiple stages. Alternatively or additionally, other means of cooling may be used in said precooler, such as vaporizing other single component refrigerants (such as another hydrocarbon, an HFC, CFC, or CO₂) or vaporizing mixed refrigerant in a single or plurality of stages.

Scrub column 618 separates the pretreated pressurized natural gas feed stream in line 600 into a bottoms liquid in line 634 that is enriched in hydrocarbons heavier than methane and a first overhead vapor in line 620 that is enriched in methane. A portion of the bottoms liquid may be withdrawn via line 630 and vaporized in reboiler 632 to provide boilup for the scrub column 618. The reboiler 632 may cool a portion (not shown) of the pretreated pressurized natural gas feed stream in line 600 to provide heat therein for vaporizing the liquid in line 630. The scrub column 618 may also have an intermediate reboiler (not shown) above the bottom of the scrub column 618 and below the location of line 600, and this reboiler also may be heated by a portion of the pretreated pressurized natural gas feed stream in line 600.

The bottoms liquid in line 634 may flow to a NGL fractionation system 636, which for example may be a NGL fractionation system as described above with reference to FIG. 5 or any suitable generic NGL fractionation system. The NGL feed stream typically is reduced in pressure (not shown) and separated in or more additional distillation columns including any of a demethanizer, a deethanizer, a depropanizer, a debutanizer, and a depentanizer to provide two or more hydrocarbon fractions. In the embodiment depicted in FIG. 6, three streams of recovered hydrocarbons are withdrawn and exported from the integrated LNG production and NGL recovery system as C2, C3, and C4 product streams representing streams enriched in ethane, propane, and butane plus isobutane, respectively. Optionally, unrecovered liquid hydrocarbons are withdrawn from the NGL recovery system via line 638 and combined with the first overhead vapor stream in line 620 to form the combined stream in line 662.

The scrub column 618 is refluxed using a reflux drum 611. The first overhead vapor stream of line 620, or optionally, the combined stream of line 662 of unrecovered liquid hydrocarbons in line 638 and the first overhead vapor stream of line 620 is cooled in cooler 664, by vaporizing propane or another suitable refrigerant, to a temperature preferably between −20 and −70° F. to form a cooled overhead stream enriched in methane in line 666. As with the optional precooling of natural gas feed 600 prior to introduction thereof into scrub column 618, other suitable refrigerants may, for example, include other single component refrigerants (such as other hydrocarbons, HFCs, CFCs, or CO₂) or multicomponent refrigerants.

Preferably, cooler 664 and precooler 610 utilize the same refrigerant, such as where cooler 664 and precooler 610 are supplied with refrigerant by the same closed or open loop refrigerant system. For example, cooler 664 and precooler 610 may be supplied with a single component refrigerant by the same closed loop refrigerant system. Closed loop refrigerant systems are well known in the art, and any suitable refrigerant system may be used to supply refrigerant to the cooler 664 and precooler 610.

Referring now to FIG. 9, an exemplary closed loop refrigerant sytem for supplying single component refrigerant (e.g. propane) to cooler 664 and precooler 610 is shown. Gaseous refrigerant is compressed in multi-stage refrigerant compressor 900. Resulting stream 902 may be totally condensed in condenser 904 (which may for example use ambient temperature water or air to cool stream 902). Liquid stream 906 may be throttled in valve 907 and partially vaporized in the higher-pressure evaporator of precooler 610 (which in this exmaple comprises at least two cooling stages in the form of said high-pressure evaporator and a lower-pressure evaporator) to produce two-phase stream 908, which may then be separated in phase separator 909. The vapor portion 910 may be introduced between the stages of compressor 900 as a high-pressure stream. The liquid portion 911 may be throttled in valve 912 and partially vaporized in the lower-pressure evaporator of precooler 610 to produce two-phase stream 913, which may then be separated in phase separator 914. The vapor portion 915 may be introduced between the stages of compressor 900 as a medium-pressure stream. The liquid portion 916 may be throttled in valve 917, totally vaporized in the evaporator of cooler 664 (at a still lower pressure than that of lower-pressure evaporator of precooler 610), and introduced into compressor 900 as a low-pressure stream 917. Therefore, refrigeration may be supplied at three temperature levels corresponding to the three evaporator pressures. It is also possible to have more or less than three evaporators and temperature/pressure levels. Evaporators and phase separators may be combined within common shells. Cooled streams may pass through tube bundles or plate-and-fin cores enclosed in evaporator shells. Stream 902 may be supercritical at a pressure higher than the critical pressure, for example. It may then be cooled in condenser 904 without phase change to produce a dense fluid 906. Supercritical stream 906 may become a partial liquid after being throttled.

Referring back to FIG. 6, placement of the cooler 664 for acceptance of line 662 is an alternative to having more precooling stages placed and implemented for precooling the natural gas feed 600 prior to introduction thereof into the scrub column 618. Applicants found that such configuration provided an efficient solution for the production of reflux when utilizing a main exchanger 624 comprising only two bundles (i.e., cold (upper) bundle and warm (lower) bundle). It is one object of current invention to combine the warm and middle bundles of a traditional three bundle main heat exchanger (as shown on FIG. 7) to save on the significant capital costs associated with a three-bundle exchanger while maintaining high process efficiency of the three-bundle exchanger.

As one skilled in the art may now recognize, when utilizing a two bundle main exchanger 624, stream 626 exits the main exchanger 624 at a temperature far lower or colder than is required to be used as reflux for scrub column 618. Thus, it would be inefficient to use LNG reflux stream 626 (that then becomes stream 668) on its own for reflux because such a cold or refrigerated stream is not required.

Instead, in the embodiment depicted in FIG. 6 cooled overhead stream 666 is used in combination with LNG reflux stream 626 from main exchanger 624 to provide reflux to the scrub column 618. While stream 666 may not provide all of the reflux necessary for scrub column 618, stream 666 provides an alternative source of reflux for the configuration illustrated in FIG. 6. Thus, a part of the cooling duty needed to generate the reflux is provided at a warmer temperature using the refrigerant used in cooler 664. While the configuration does contemplate mixing streams at two different temperatures (i.e., streams 666 and 668), thus inherently introducing inefficiency (and notably a reason not to contemplate arranging in such a configuration), Applicants found that the inefficiencies of mixing the two streams 666 and 668 at two different temperatures were far outweighed by the benefits of removing less of the reflux from the main exchanger 624 via stream 626. It is preferred that the flow rate of cooled overhead stream 666 is greater than that of LNG reflux stream 626, such that the cooled overhead stream provides the majority of the mixture formed by combining the two streams. The flow rate of the LNG reflux stream is preferably less than 10%, more preferably less than 5%, of the sum of the flow rates of the LNG reflux stream and the cooled overhead stream.

Referring back to FIG. 6, and as previously noted, cooled overhead stream in line 666 is combined with the liquefied natural gas reflux stream in line 668. The LNG reflux stream in line 668 is generated by withdrawing from the main heat exchanger 624 via line 626, and pumping via pump 627, a portion of the single phase, LNG product produced by further cooling and fully condensing (and optionally subcooling) a second overhead vapor stream enriched in methane in line 660 in the warm bundle of main exchanger 624. The combined two-phase stream in line 670 of the cooled overhead stream in line 666 and liquefied natural gas reflux stream in line 668 is separated in reflux drum 611 to yield a liquid reflux stream in line 613 and the aforementioned second overhead vapor stream enriched in methane in line 660. Although in the embodiment depicted in FIG. 6 the cooled overhead stream in line 666 and the LNG reflux stream in line 668 are combined into a combined two-phase stream in line 670 prior to the introduction thereof into reflux drum 611, an alternative option (not depicted) is for the cooled overhead stream and the LNG reflux stream to be introduced separately into the reflux drum 611 such that the two streams are combined to form the two-phase mixture in the reflux drum itself. The remainder of the LNG product, that is obtained from the warm bundle of main heat exchanger 624 and not withdrawn via line 626, is subcooled (or further subcooled) in the cold bundle of main heat exchanger 624 and is withdrawn as a subcooled liquefied natural gas product in line 628. The reflux drum 611 represents an additional separation stage of the scrub column 618.

Importantly, the configuration of the embodiment disclosed in FIG. 6 is particularly advantageous when the required temperature of the reflux drum 611 for heavy component removal is slightly lower (colder) than can be provided by the cooler 664 used to cool the stream in line 662. In this embodiment, the bulk of the refrigeration required to provide reflux to the scrub column 618 is provided at a relatively warm temperature by cooler 664, and then additional refrigeration at a colder temperature is provided as required by the LNG reflux stream 668. This requirement may happen only seasonally. For example, if cooler 664 uses propane as refrigerant, during the summer months the ambient temperature of the air and/or cooling water that cools the propane supplied to cooler 664 may be high enough to increase the required discharge pressure of the propane compressor that supplies propane to cooler 664 to the point that the propane compressor is incapable of providing enough head to achieve the needed suction pressure and temperature.

Optionally, an economizer heat exchanger similar to 114 in FIG. 1 may be incorporated to warm the second overhead vapor stream in line 660 using the pretreated pressurized natural gas feed stream 600 before the second overhead vapor stream in line 660 is introduced into the main exchanger 624.

Refrigeration to main heat exchanger 624 may be provided by any known refrigeration system used in the production of LNG. For example, as shown in FIG. 6, a single mixed refrigerant (MR) system may be used in which a liquid refrigerant is provided via line 652 and a vapor refrigerant is provided via line 656. The vapor in line 656 is cooled and condensed in main heat exchanger 624 and expanded through throttling valve 658 to provide a first vaporizing refrigerant to the cold (upper) bundle of the main heat exchanger 624 and subsequently to the warm (lower) bundle of the main heat exchanger 624. Liquid refrigerant 652 is cooled in main heat exchanger 624 to yield subcooled liquid refrigerant and expanded through throttling valve 654, and combined with vaporizing refrigerant from the cold (upper) bundle at a location near the cold end of the warm bundle of the main heat exchanger 624. As an alternative to throttling valves 654 and/or 658, as well as the LNG product letdown valve, expansion may be effected by isentropic dense fluid expanders (hydraulic turbines).

The refrigerant streams are completely vaporized and leave main heat exchanger 624 as refrigerant vapor via line 650. The mixed refrigerant vapor flows to a refrigeration system (not shown) where it is compressed, cooled by multiple stages of vaporizing propane or other suitable refrigerant, and separated to provide liquid refrigerant 652 and lighter vapor refrigerant 656.

Although in the embodiment depicted in Figure the LNG reflux stream in line 668 is obtained solely from LNG product withdrawn via line 626 from the main heat exchanger 624 between the warm and cold bundles, other sources of LNG can additionally and/or alternatively be used to provide the LNG reflux stream. For example, FIG. 8 shows another embodiment of the invention, which varies from that depicted in

FIG. 6 only in terms of the source of the LNG reflux stream. More specifically, in the embodiment depicted in FIG. 8 all of the LNG product, produced by cooling and fully condensing (and optionally subcooling) the second overhead vapor stream enriched in methane in line 660 in the warm bundle of main exchanger 624, is then subcooled (or further subcooled) in the cold bundle of main heat exchanger 624 and is withdrawn as a subcooled liquefied natural gas product in line 827. A portion of this subcooled liquefied natural gas product is then diverted via line 895 to pump 627 and pumped to provide the LNG reflux stream in line 668. It should be noted that although in FIG. 8 the LNG reflux stream is shown as being taken, via line 895, directly from the subcooled LNG product as it is being withdrawn from the main heat exchanger 624 via line 827, another option would be to take the LNG reflux stream from LNG derived from the subcooled LNG product via further processing or storage of the latter. For example, the LNG reflux stream may be taken from an LNG storage tank (not depicted) in which subcooled LNG product withdrawn from the main heat exchanger has been temporarily stored.

While using a portion of the subcooled LNG product, as shown in FIG. 8, as the LNG reflux stream is not as efficient as using a portion of the LNG product withdrawn from the main heat exchanger 624 between the warm and cold bundles, as shown in FIG. 6, the arrangement in FIG. 8 does avoid the need for a separate penetration of the main cryogenic exchanger (i.e. a penetration separate from that already required for withdrawal of the subcooled LNG product) and can therefore be more easily used in retrofit/debottlenecking of an existing plant.

FIG. 7 illustrates a traditional liquefaction system utilizing a three bundle main exchanger 780. This three-bundle main exchanger 780 includes a warm bundle delineated by the exit point of stream 782, a middle bundle between the re-entry point of stream 760 and the introduction of mixed refrigerant through valve 654, and a cold bundle, typically of smaller diameter, above the introduction of mixed refrigerant through valve 654. Overhead vapor product in line 720 is optionally split into streams 722 and 784. Stream 722 is combined with the reinjection stream 638 from the fractionation system 636. Combined stream 774 is cooled by refrigerant such as propane in heat exchanger 776 and the resulting stream 778 enters the warm bundle of the main exchanger 780 where it is partially liquefied. Two-phase stream 782 is optionally combined with the stream 784 that bypasses the main exchanger 780. The bypass is used to control the reflux temperature and amount of reflux, however, use of this type of control is highly inefficient. The combined stream 786 is separated in the reflux drum 611 into the reflux stream 613 and the second overhead vapor product 788. Stream 760 via line 760 is totally condensed and sub-cooled in the main exchanger 780 to produce LNG product stream 628. Optionally, to limit the excess reflux, a portion of liquid stream in line 613 may be combined, via line 728, with the vapor stream 788, to form a combined stream in line 760 that is then sent to the main heat exchanger 780. Stream 760 is totally condensed and sub-cooled in the main exchanger 780 to produce LNG product stream 628.

Optionally, reinjection stream 638 can be introduced directly into the reflux drum 611, cooled in a separate circuit in the warm bundle of the MCHE and then put into the reflux drum 611, or introduced directly into the scrub column 618 (not shown).

In the above described embodiments of the invention, other NGL fractionation systems may be used depending on the particular hydrocarbons to be recovered. For example, the system may utilize a depentanizer column to recover high purity pentanes and a residual product containing hydrocarbons heavier than pentane. A portion of the pentanes may be returned as an unrecovered hydrocarbon to scrub column 118/618. In another alternative, the demethanizer is not used and the deethanizer is operated to withdraw the ethane liquid product at an intermediate stage and to withdraw a mixture of methane and ethane vapor from the reflux drum as a recovered hydrocarbon product. A portion of this vapor may be withdrawn as an unrecovered hydrocarbon product and dissolved in the unrecovered liquid hydrocarbon mixture as described above.

The following Examples illustrate an embodiment of the present invention but do not limit embodiments of the invention to any of the specific details described therein.

EXAMPLE 1

A process simulation was carried out to illustrate the embodiment of FIG. 1. A pre-purified natural gas stream in line 100 has a flow rate of 100,000 lbmol/hr and pressure of 960 psia and contains (in mole %) 1.9% helium, 5.8% nitrogen, 83.2% methane, 7.1% ethane, 2.3% propane, 0.4% isobutane, 0.6% butane, 0.1% isopentane, 0.2% pentane, and 0.2% hexanes. The stream is cooled by three stages of propane cooling to −29° F., is further cooled in the economizer heat exchanger to −62.8° F., and is fed to scrub column 118. The column operates at an average pressure of 886 psia. Column overhead in line 120 at a flow rate of 104,770 lbmol/hr is warmed from −73° F. to −32° F. against the feed in heat exchanger 114. The resulting stream in line 122 is cooled and liquefied in passage 123 of the warm bundle of main heat exchanger 124 to provide a condensed methane-enriched stream in line 125. A portion of this liquid is withdrawn via line 126 at a flow rate of 10,943 lbmol/hr and temperature of −197.6° F. The stream is pumped in pump 127 to the scrub column pressure, since the liquid head typically is not sufficient to overcome the pressure drop in heat exchanger 124. The remainder of the liquid in line 125 is subcooled in passage 128 and withdrawn from the cold bundle of the exchanger as a liquefied natural gas product in line 129 at a flow rate of 93,827 lbmol/hr and a temperature of −228.8° F. The product stream may be further processed to recover helium before being reduced in pressure to the storage pressure.

The scrub column bottoms stream is withdrawn via line 134 at a flow rate of 1862 lbmol/hr and is sent to NGL fractionation system 136, which is a series of distillation columns as shown in FIG. 5 comprising a demethanizer producing a methane-ethane mixture as a vapor overhead product, a deethanizer producing high purity ethane as a liquid overhead product, a depropanizer producing high purity propane as a liquid overhead product, and a debutanizer producing high purity butane as a liquid overhead product. The ethane, propane, and butane liquids have purities in excess of 98 mole %. The methane and ethane mixture from the demethanizer is withdrawn as a recovered hydrocarbon and is used as fuel.

Unrecovered liquid propane and butane in lines 575 and 577 are combined in line 138, cooled by propane refrigeration to −32.3° F. in heat exchanger 581, and pumped to the scrub column pressure in pump 583. The unrecovered propane in line 575 is 50% of the overhead stream in depropanizer overhead line 541 and the unrecovered butane in line 577 butane is 60% of the overhead stream in debutanizer overhead line 559. The combined unrecovered hydrocarbon stream in line 579 has a flow rate of 1116 lbmol/hr and a composition (in mole %) of 39% propane, 60% butane plus isobutanes, and 1% components heavier than butane. The pumped unrecovered liquid hydrocarbon is combined with the liquefied methane-containing reflux stream from pump 127 and the combined stream is introduced into the top of scrub column 118.

EXAMPLE 2

Additional process simulations were carried out to compare the embodiment of FIG. 6 with the configuration of a three bundle system of FIG. 7. The main exchanger surface area was held constant for the two options simulated.

In both cases, the LNG plant was set to produce about 5 million metric tons per annum of LNG. Referring to the configuration of FIG. 7, feed 600 entering the scrub column 618 is at the pressure of 800 psia and temperature of 5° F. It contains 1% of nitrogen, 91% of methane, 5.3% of ethane, 1.5% of propane, 0.014% of benzene, and the balance being heavier hydrocarbons. The column operates at the pressure of 800 psia and contains 8 theoretical stages, including the reboiler. The partial condenser is an additional stage of separation. The feed is introduced on stage 5.

The overhead vapor product 720 leaves the top of the column at −7.1° F. The second stage of the column is at 0.8° F. Stream 720 is combined with the reinjection stream 638 and cooled by propane in a kettle-type heat exchanger to −28.2° F. Resulting stream 778 is further cooled and partially liquefied in the warm bundle of the MCHE to −60.0° F. Two-phase stream 782, 786 enters the reflux drum 611 where it is separated into the liquid stream 613 and the second overhead vapor product 788, 760. No bypass is assumed. About 45% of liquid stream 613, stream 728, is re-injected into stream 760.

The remaining 55%, about 6% of feed 600, is used as reflux. Stream 760, including the re-injected stream 728, about 99.5% of the feed 600, still at −60.0° F., is introduced into the middle bundle of the MCHE and fully liquefied and subcooled in the MCHE to produce subcooled LNG product 628. The scrub column bottoms product 634, about 0.7% of the feed stream 600, at −230.0° F., is fractionated into NGL products, part of it re-injected as stream 638.

The scrub column operation is determined by the allowable concentration of benzene in LNG product, kept at one part per million.

Referring to FIG. 6 (current invention), the feed and scrub column conditions and geometry are about the same as in the previous calculation (FIG. 7).

The first overhead vapor stream 620 leaves the top of the column at −1.3° F. (close to the temperature of the second stage in the previous example). It is combined with a reinjected stream 638 and cooled by vaporizing propane in a kettle-type heat exchanger 664 to −29.4° F. Resulting stream 666 is combined with LNG reflux stream 626, 668 which is at −193.5° F. Resulting stream 670 enters the reflux drum 611 at −32.7° F. Stream 626 is only about 1.4% of the combined stream 670 or the feed stream 600. It provides a bit of additional cooling required for optimum operation. Stream 670 is separated into the second overhead vapor stream 660 and the liquid reflux stream 613 which is used as reflux for the scrub column 618. The reflux is about 2.5% of the feed stream 600. Stream 660 is introduced into the warm bundle of the two-bundle MCHE and fully liquefied in the warm bundle to produce a fully condesned LNG product. A portion of the fully-condensed LNG product is withdrawn between the warm and cold bundles and used as LNG reflux stream 626 to contribute to the reflux for the scrub column 618 as discussed above. The remainder of the fully-condensed LNG product is subcooled in the cold bundle of the two bundle MCHE to produce subcooled LNG product stream 628. The scrub column bottoms product 634, about 0.7% of the feed 600, at −217.4° F., is fractionated into NGL products, and part of it re-injected as stream 638.

As before, the scrub column operation is determined by the allowable concentration of benzene in LNG product, kept at one part per million.

TABLE 1 FIG. 6 Configuration FIG. 7 Configuration LNG Production 100.8% 100%

Table 1 compares the two cases. Compared to prior art, the configuration shown on FIG. 6 produces 0.8% more LNG product, a modest improvement, almost within the accuracy of the method. However, the MCHE cost savings (elimination of a bundle) are quite substantial. 

1. A process for the liquefaction of natural gas and the recovery of components heavier than methane from the natural gas, wherein the process comprises: (a) introducing a natural gas feed into a first distillation column and separating in the first distillation column the natural gas feed into an overhead vapor enriched in methane and a bottoms liquid enriched in components heavier than methane; (b) withdrawing from the first distillation column a first overhead vapor stream enriched in methane and a bottoms liquid stream enriched in components heavier than methane; (c) cooling the first overhead vapor stream enriched in methane to provide a cooled overhead stream enriched in methane, combining the cooled overhead stream enriched in methane with a liquified natural gas reflux stream to provide a two-phase mixture, and separating the two-phase mixture to provide a liquid reflux stream and a second overhead vapor stream enriched in methane; (d) introducing the liquid reflux stream into the first distillation column to provide reflux to the distillation column; (e) introducing the second overhead vapor stream enriched in methane into a main heat exchanger comprising only two tube bundles, said bundles consisting of a warm bundle and a cold bundle, and cooling and liquifying the second overhead vapor stream in the warm bundle to provide a single-phase, liquefied natural gas product; and (f) subcooling at least a portion of the liquified natural gas product in the cold bundle of the main heat exchanger to provide a subcooled liquified natural gas product, and withdrawing the subcooled liquified natural gas product from the main heat exchanger.
 2. The process of claim 1, wherein the liquefied natural gas reflux stream comprises: a portion of the single-phase, liquefied natural gas product, withdrawn from the main heat exchanger between the warm and cold bundles; a portion of the subcooled liquefied natural gas product; and/or liquefied natural gas obtained from processing and/or storing at least a portion of the subcooled liquefied natural gas product.
 3. The process of claim 1, wherein the method further comprises the step of: withdrawing from the main heat exchanger, between the warm and cold bundles, a first portion of the liquified natural gas product, the liquified natural gas reflux stream comprising said first portion of the liquified natural gas product; and wherein step (f) comprises subcooling a second portion of the liquified natural gas product in the cold bundle of the main heat exchanger to provide a subcooled liquified natural gas product, and withdrawing the subcooled liquified natural gas product from the main heat exchanger.
 4. The process of claim 1, wherein the method further comprises the steps of: separating the bottoms liquid stream in one or more additional distillation columns to provide one or more hydrocarbon product streams selected from the group consisting of a residual vapor stream comprising methane, a liquid stream enriched in ethane, a liquid stream enriched in propane, a liquid stream enriched in butane, and a liquid stream enriched in pentane; and withdrawing as recovered hydrocarbons all or a portion of any of the one or more hydrocarbon product streams.
 5. The process of claim 4, wherein step (c) comprises: combining the first overhead vapor stream enriched in methane with a stream of unrecovered hydrocarbons, cooling the combined stream to provide the cooled overhead stream enriched in methane, combining the cooled overhead stream enriched in methane with the liquified natural gas reflux stream to provide the two-phase mixture, and separating the two-phase mixture to provide the liquid reflux stream and the second overhead vapor stream enriched in methane.
 6. The process of claim 5, wherein the stream of unrecovered liquid hydrocarbons comprises any of: (I) a portion of the liquid stream enriched in ethane, (II) a portion of the liquid stream enriched in propane, (III) a portion of the liquid stream enriched in butane, (IV) a portion of the liquid stream enriched in pentane, and (V) all or a portion of the residual vapor stream dissolved in a portion of the liquid stream enriched in propane and/or a portion of the liquid stream enriched in butane and/or a portion of the liquid stream enriched in pentane.
 7. The process of claim 1, wherein in step (c) the first overhead vapor stream is cooled to a temperature of from −20 to −70° F. (−29 to −57° C.).
 8. The process of claim 1, wherein the natural gas feed is cooled prior to being introduced into the first distillation column.
 9. The process of claim 8, wherein the natural gas feed is cooled to a temperature of from 10 to −30° F. (12 to −34° C.) prior to being introduced into the first distillation column.
 10. The process of claim 8, wherein the cooling of the first overhead vapor stream enriched in methane to provide the cooled overhead stream enriched in methane, and the cooling of the natural gas feed prior to said natural gas feed being introduced into the first distillation column, is carried out using the same refrigerant.
 11. The process of claim 1, wherein the liquid reflux stream is introduced into the top of the first distillation column.
 12. The process of claim 1, wherein boilup for the first distillation column is provided by vaporizing a portion of the bottoms liquid in a reboiler.
 13. The process of claim 1, wherein the cooling and liquefying of the second overhead vapor stream in the warm bundle of the main heat exchanger is effected by indirect heat exchange with a first vaporizing refrigerant provided by reducing the pressure of a first cooled multicomponent liquid refrigerant.
 14. The process of claim 13, wherein the first cooled multicomponent liquid refrigerant is provided by cooling a first multicomponent refrigerant in the warm bundle of the main heat exchanger.
 15. The process of claim 1, wherein the subcooling of the at least a portion of the liquified natural gas product in the cold bundle of the main heat exchanger is effected by indirect heat exchange with a second vaporizing refrigerant provided by reducing the pressure of a second cooled multicomponent liquid refrigerant.
 16. The process of claim 15, wherein the second cooled multicomponent liquid refrigerant is provided by cooling a second multicomponent refrigerant in the warm and cold bundles of the main heat exchanger.
 17. The process of claim 1, wherein the flow rate of the cooled overhead stream enriched in methane is greater than the flow rate of the liquified natural gas reflux stream, such that the cooled overhead stream provides the majority of the two-phase mixture.
 18. The process of claim 17, wherein the flow rate of the liquified natural gas reflux stream is less than 10% of the sum of the flow rates of the liquified natural gas reflux stream and the cooled overhead stream.
 19. An apparatus for the liquefaction of natural gas and the recovery of components heavier than methane from the natural gas, wherein the apparatus comprises: (a) a first distillation column adapated to separate a natural gas feed into an overhead vapor enriched in methane and a bottoms liquid enriched in components heavier than methane and thereby provide a first overhead vapor stream enriched in methane and a bottoms liquid stream enriched in components heavier than methane; (b) a cooling system adapted to cool the first overhead vapor stream enriched in methane to provide a cooled overhead stream enriched in methane; (c) a reflux drum adapted to receive a two-phase mixture, formed from the combination of the cooled overhead stream enriched in methane and a liquified natural gas reflux stream, and adapted to separate the two-phase mixture to provide a liquid reflux stream and a second overhead vapor stream enriched in methane; (d) piping adapted to introduce the cooled overhead stream and the liquified natural gas reflux stream, as separate streams or as a combined stream, into the reflux drum; (e) piping adapted to introduce the liquid reflux stream into the first distillation column to provide reflux to the distillation column; (f) a main heat exchanger comprising only two tube bundles, said bundles consisting of a warm bundle and a cold bundle, the warm bundle being adapted to cool and liquify the second overhead vapor stream to provide a single-phase, liquified natural gas product, and the cold bundle being adapted to subcool at least a portion of the liquified natural gas product to provide a subcooled liquified natural gas product; (g) piping adapted to introduce the second overhead vapor stream into the warm bundle of the main heat exchanger; and (h) piping adapted to withdraw the liquified natural gas product stream from the cold bundle of the main heat exchanger.
 20. The apparatus of claim 19, wherein said piping adapted to introduce the liquified natural gas reflux stream into the reflux drum is adapted to withdraw a portion of the liquefied natural gas product from the main heat exchanger between the warm and cold bundles, to withdraw a portion of the subcooled liquefied natural gas product and/or to withdraw liquefied natural gas obtained from processing and/or storing at least a portion of the subcooled liquefied natural gas product, the liquified natural gas reflux stream comprising said portion of the liquefied natural gas product, said portion of the subcooled liquefied natural gas product and/or said liquefied natural gas obtained from processing and/or storing at least a portion of the subcooled liquefied natural gas product.
 21. The apparatus of claim 19, wherein the apparatus further comprises: (i) one or more additional distillation columns adapted to separate the bottoms liquid stream in provide one or more hydrocarbon product streams selected from the group consisting of a residual vapor stream comprising methane, a liquid stream enriched in ethane, a liquid stream enriched in propane, a liquid stream enriched in butane, and a liquid stream enriched in pentane; and (j) piping adapted to withdraw as recovered hydrocarbons all or a portion of any of the one or more hydrocarbon product streams.
 22. The apparatus of claim 21, wherein the apparatus further comprises piping adapted to introduce a stream of unrecovered hydrocarbons into the the first overhead vapor stream enriched in methane prior to the resulting combined stream being cooled in the cooling system, wherein the stream of unrecovered liquid hydrocarbons is withdrawn from one of the additional distillation columns and comprises any of: (I) a portion of the liquid stream enriched in ethane, (II) a portion of the liquid stream enriched in propane, (Ill) a portion of the liquid stream enriched in butane, (IV) a portion of the liquid stream enriched in pentane, and (V) all or a portion of the residual vapor stream dissolved in a portion of the liquid stream enriched in propane and/or a portion of the liquid stream enriched in butane and/or a portion of the liquid stream enriched in pentane.
 23. The apparatus of claim 19, wherein the apparatus further comprises a precooling system adapted to cool the natural gas feed prior to said feed being introduced into the first distillation column.
 24. The apparatus of claim 23, wherein said cooling system, adapted to cool the first overhead vapor stream enriched in methane to provide a cooled overhead stream enriched in methane, and said precooling system, adapted to cool the natural gas feed prior to said feed being introduced into the first distillation column, are adapted to utilize the same refrigerant.
 25. The apparatus of claim 19, wherein the main heat exchanger is a wound coil heat exchanger comprising only two wound coil tube bundles, said bundles consisting of said warm bundle and said cold bundle.
 26. The process of claim 1, wherein the main heat exchanger is a wound coil heat exchanger comprising only two wound coil tube bundles, said bundles consisting of said warm bundle and said cold bundle. 